1. Field of the Invention
The invention relates generally to drilling through earth formations, and more specifically to simulating the drilling performance of a drilling tool assembly in drilling a wellbore through earth formations. The invention also relates to methods for modeling the dynamic response of a drilling tool assembly, methods for designing a drilling tool assembly, and methods for optimizing the performance of a drilling tool assembly.
2. Background Art
FIG. 1 shows one example of a conventional drilling system for drilling through earth formation. The drilling system includes a drilling rig 10 used to turn a drilling tool assembly 12 which extends downward into a wellbore 14. The drilling tool assembly 12 includes a drill string 16, and a bottomhole assembly (BHA) 18, attached to the distal end of the drill string 16.
The drill string 16 comprises several joints of drill pipe 16a connected end to end through tool joints 16b. The drill string 16 transmits drilling fluid (through its hollow core) and transmits rotational power from the drill rig 10 to the BHA 18. Additional components may also be included as part of the drilling tool assembly, including components such as subs, pup joints, etc.
The BHA 18 is generally considered to include at least a drill bit 20. Typical BHAs may include additional components disposed between the drill string 16 and the drill bit 20. Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (MWD) tools, logging-while-drilling (LWD) tools, subs, hole enlargement devices (e.g., hole openers and reamers), jars, accelerators, thrusters, downhole motors, and rotary steerable systems.
In general, drilling tool assemblies 12 may include other drilling components and accessories, such as special valves, including kelly cocks, blowout preventers, and/or safety valves. Additional components included in a drilling tool assembly 12 may be considered a part of the drill string 16 or a part of the BHA 18 depending on their locations in the drilling tool assembly 12.
The drill bit 20 of the BHA 18 may be any type of drill bit suitable for drilling earth formation. Two common types of earth boring bits used for drilling earth formations are fixed-cutter bits and roller cone bits. One example of a fixed-cutter bit is shown in FIG. 2. One example of a roller cone bit is shown in FIG. 3.
Referring to FIG. 2, fixed-cutter bits (also called drag bits) 21 typically comprise a bit body 22 having a threaded connection at one end 24 and a cutting head 26 formed at the other end. The head 26 of the fixed-cutter bit 21 typically comprises a plurality of blades 28 arranged about the rotational axis of the bit and extending radially outward from the bit body 22. Cutting elements 29 are embedded in the blades 28 to cut through earth formation as the bit is rotated on the earth formation. Cutting elements 29 of fixed-cutter bits, such as the one shown in FIG. 2, typically comprise polycrystalline diamond compacts (PDC) or specially manufactured diamond or other superabrasive material cutters. These bits are typically referred to as PDC bits.
Referring to FIG. 3, roller cone bits 30 typically comprise a bit body 32 having a threaded connection at one end 34 and one or more legs (typically three) extending from the other end. A roller cone 36 is mounted on each of the legs and is able to rotate with respect to the bit body 32. On each cone 36 of the bit 30 are a plurality of cutting elements 38, typically arranged in rows about the surface of the cone 36 to contact and cut through formation encountered by the bit. Roller cone bits 30 are designed such that as a drill bit rotates on earth formation in a wellbore, the cones 36 of the bit 30 roll on the bottom surface of the wellbore (called the “bottomhole”) and the cutting elements 38 scrape and crush the formation beneath them. The cutting elements 38 on the roller cone bit 30 may comprise milled steel teeth formed on the surface of the cones 36 or inserts embedded in the cones. Typically, inserts are tungsten carbide inserts or polycrystalline diamond compacts. In the case of roller cone bits or fixed cutter bits hardfacing may be applied to the surface of the cutting elements and the cones or blades of the bit to improve the wear resistance of the cutting structure.
For a drill bit 20 to drill through formation, sufficient rotational moment and axial force must be applied to the bit 20 to cause the cutting elements of the bit 20 to cut into and/or crush formation as the bit is rotated. The axial force applied to the bit is a portion of the weight of the drilling tool assembly. The drilling tool assembly is typically supported at the rig by a suspending mechanism (or hook), and the portion of the weight of the drilling tool assembly supported at the rig 10 by the suspending mechanism is typically referred to as the hook load. The portion of the drilling tool assembly weight applied as an axial force on the bit 20 is typically referred to as the “weight on bit” (WOB). The rotational moment applied to the drilling tool assembly 12 at the drill rig 10 (usually by a rotary table or top drive mechanism) to turn the drilling tool assembly 12 is referred to as the “rotary torque”. The speed at which the rotary table or top drive mechanism rotates the drilling tool assembly 12, typically measured in revolutions per minute (RPM), is referred to as the “rotary speed”.
During drilling, the actual WOB is not constant. Some of the fluctuation in the force applied to the bit may be the result of the bit contacting the formation having harder and softer portions that break unevenly. However, in most cases, the majority of the fluctuation in the WOB can be attributed to drilling tool assembly vibrations in the wellbore. Drilling tool assemblies can extend more than a mile in length while being less than a foot in diameter. As a result, these assemblies are relatively flexible along their length and may vibrate when driven rotationally by a rotary table. Several modes of vibration are possible for drilling tool assemblies. In general, drilling tool assemblies may experience torsional, axial and lateral vibrations. Although partial damping of vibration may result due to viscosity of drilling fluid, friction of the drill string rubbing against the wall of the wellbore, energy absorbed in drilling the formation, and drilling tool assembly impacting with wellbore wall, these sources of damping are typically not enough to suppress vibrations completely.
Vibrations of a drilling tool assembly have been difficult to predict because different forces may combine to produce the various modes of vibration, and models for simulating the response of an entire drilling tool assembly including a drill bit interacting with formation in a drilling environment have not been available. Drilling tool assembly vibrations are generally undesirable, not only because they are difficult to predict, but also because they can significantly affect the instantaneous force applied on the bit. This can result in the bit not operating as expected. For example, vibrations can result in off-centered drilling, lack of control in the direction of drilling, slower rates of penetration, excessive wear of the cutting elements, or premature failure of the cutting elements and the bit. Lateral vibration of the drilling tool assembly may be a result of radial force imbalances, mass imbalance, and bit/formation interaction, among other things. Lateral vibration results in poor drilling tool assembly performance, overgage hole drilling, out-of-round, or “lobed” wellbores and premature failure of both the cutting elements and bit bearings.
When the bit wears out or breaks during drilling, the entire drilling tool assembly must be lifted out of the wellbore section-by-section and disassembled in an operation called a “pipe trip”. In this operation, a heavy hoist is required to pull the drilling tool assembly out of the wellbore in stages so that each stand of pipe (typically pipe sections of about 90 feet) can be unscrewed and racked for the later re-assembly. Because a drilling tool assembly may extend for more than a mile, pipe trips can take several hours and can pose a significant expense to the wellbore operator and drilling budget. Therefore, the ability to design drilling tool assemblies which have increased durability and longevity, for example, by minimizing the wear on the drilling tool assembly due to vibrations, is very important and greatly desired to minimize pipe trips out of the wellbore and to more accurately predict the resulting geometry of the wellbore drilled.
Simulation methods have been previously introduced which characterize either the interaction of a bit with the bottomhole surface of a wellbore under fixed condition or the dynamics of a bottomhole assembly (BHA) with representative factors assumed for the influence of the drill string and the drill bit. However, no prior art simulation techniques have been developed to cover the dynamic modeling of an entire drilling tool assembly which includes the simulated interaction of the drill bit with the bottomhole surface, until the development of methods disclosed in U.S. Pat. No. 6,785,641, filed Oct. 11, 2000 and incorporated herein by reference. Prior to this disclosure, the dynamic response of a drilling tool assembly or the effect of a change in configuration on drilling tool assembly performance could not be accurately predicted. Thus, numerous sensors, measurement devices, and control systems were employed in drilling to determine a more accurate prediction of the drilling response of a given drilling tool assembly, which significantly added to the overall cost of drilling the well.
As disclosed in U.S. Pat. No. 6,785,641, simulation methods for PDC drill bits have been previously disclosed, such as the methods described in SPE Paper No. 15618 by T. M. Warren et. al., entitled “Drag Bit Performance Modeling” and the methods disclosed in U.S. Pat. No. 4,815,342, U.S. Pat. No. 5,010,789, U.S. Pat. No. 5,042,596, and U.S. Pat. No. 5,131,479 to Brett et al. Also disclosed are methods for defining the bit geometry, and methods for modeling forces on cutting elements and methods for determining cutting element wear based. Modeling cutting element/earth formation interaction is also discussed in SPE Paper No. 15617 by T. M. Warren et al., entitled “Laboratory Drilling Performance of PDC Bits”.
A method for determining the interaction between a roller cone bit and earth formations during drilling is described in U.S. Pat. No. 6,516,293 to Huang et al. and entitled “Method for Simulating Drilling of Roller Cone Bits and its Application to Roller Cone Bit Design and Performance”. This patent is assigned to the assignee of the present invention and incorporated herein by reference.
While prior art simulation methods, such as those described above may be used to determine an interaction of a bit with earth formation independent of a drill string, or may be used to determine the dynamics of a BHA with assumed characteristics for the drill string and bit, no prior art simulation technique covered the dynamic modeling of the entire drilling tool assembly, prior to U.S. Pat. No. 6,785,641, filed Oct. 11, 2000 and titled “Simulating the Dynamic Response of a Drilling Tool Assembly and Its Application to Drilling Tool Assembly Design Optimization and Drilling Performance Optimization,” which is incorporated herein by reference. Because previous simulation methods do not take into account the dynamic response of the entire drilling tool assembly to the calculated interaction of cutting elements with earth formation during drilling, accurately predicting the response of a given drilling tool assembly in drilling a particular formation was virtually impossible. Additionally, the change in the dynamic response of a drilling tool assembly when a component of the drilling tool assembly was changed was not well understood.
In view of the above, a method for simulating the dynamic response of an entire drilling tool assembly, which takes into account bit interaction with the bottom surface of the wellbore, drilling tool assembly interaction with the wall of the wellbore, and damping effects of the drilling fluid on the drill string is both needed and desired. Additionally, a more accurate model for predicting and visually displaying the performance of a drilling tool assembly including a fixed cutter drill bit, and for determining optimal drilling tool assembly designs and/or optimal drilling operating parameters for optimal drilling tool assembly performance for a particular drilling operation in particular earth formation is desired.